Distribution System Planning Gets a Makeover

EPRI Develops Tools to Help Distribution Planners Navigate the Complexity of a Changing Grid

By Chris Warren

Solar, electric vehicles, energy storage, and other distributed energy resources (DER) are transforming how we generate and use energy. For power distribution planners, this poses significant challenges for integrating extensive deployment of DER while operating the system safely, reliably, and cost-effectively. EPRI is working on new tools to help planners with the transition.

Skyrocketing Distributed Resources

According to the Solar Energy Industries Association (SEIA), cumulative solar photovoltaic capacity in the United States at the end of 2018 was 62.4 gigawatts—about 75 times more than was installed at the end of 2008. A significant portion of the new capacity is connected to the distribution grid. For the third quarter of 2018, SEIA reports that residential and commercial projects totaled about 1.1 gigawatts while utility-scale projects accounted for nearly 700 megawatts.

Planners expect that electrification of transportation is likely to offset much of the load reductions driven by ongoing efficiency improvements, and very rapid electrification could result in some load growth. The International Energy Agency projects the number of electric vehicles in use globally to grow from 3.1 million in 2017 to 125 million by 2030.

Many New Issues to Consider

Traditionally, planners analyze distribution feeders’ current and future state to identify actions needed to accommodate load growth. How do new neighborhoods and commercial facilities impact distribution equipment and system operation? Could transformers or power lines be subjected to power flows causing them to exceed their thermal ratings? Planners must then determine system upgrades needed for reliable system operation.

As DER are deployed extensively and bi-directional power flows become more common, projecting grid conditions becomes increasingly uncertain and variable. “It is becoming more difficult for planners to examine all the options and scenarios manually,” said Jason Taylor, a principal project manager at EPRI. “For a single feeder, they may need to decide where to deploy storage or other DER, what size to use, whether it addresses future load projections, where to upgrade grid equipment, and many other issues. Examining one issue at a time is time-intensive.”

Planners’ existing tools, processes, and methodologies cannot be used to examine all these issues quickly.

“Before you had bi-directional flow, planners could use rules of thumb and industry standard calculations to inform their decisions. The analytics were well-known and hadn’t changed in 50 years,” said Jeff Smith, who manages EPRI’s distribution planning and operations research team.

Bi-directional power flow is also changing how different parts of the electric system coordinate. Historically, frequent communication among distribution, transmission, and generation planners was unnecessary because the flow of electricity was predictable: Central power plants generated electricity, transmission lines delivered it to the distribution system, which in turn delivered it to businesses and houses. In some cases today, generation from DER on the distribution grid is exported to the transmission system.

“DER connected to the distribution system may be providing bulk system services,” said Smith. “If distribution and transmission planners continue working in silos, we can’t assume any longer that the systems will work in concert.”

“We cannot plan for distribution circuits apart from other planning activities anymore,” said Will Lowder, Duke Energy’s project director for energy storage. “We have to find a way to share our information across generation, transmission, and distribution because we will have a significant impact on each other. That is a huge driver for new long-term planning tools.”

Alternatives to Infrastructure Upgrades

DER connected to the distribution system present new options for meeting load growth beyond adding transformers, capacitors, and substations. “New energy resources could be valuable to both the distribution grid and the bulk power system,” said Taylor. “If properly designed and connected to the distribution system at the right locations, they may offer cost-effective alternatives to expensive infrastructure upgrades. However, existing planning tools and approaches are not designed to consider these options.”

“In some locations, connecting solar to the grid can cause technical problems in the distribution system, particularly if a feeder’s hosting capacity has been exceeded,” said Smith. “But the flip side of the coin is that DER can provide valuable grid services such as offsetting peak demand and providing voltage control if they’re located where those services are needed.”

Enhanced distribution planning can help utilities invest effectively. “Utilities have limited budgets for capital investments and operations and maintenance, and regulators scrutinize these budgets,” said Smith. “Smart, coordinated planning helps utilities get the most out of every dollar they spend by realizing the most value from existing grid assets and new DER. In some cases, this can help them to avoid investment in new assets. Regulators welcome these cost-containing efforts.”

Indeed, integrated distribution resource planning has been spearheaded in states where DER has grown most rapidly, including Hawaii, New York, and California. This recognizes the changing connections between distribution and transmission systems and encourages collaboration to make the best investments. It’s a significant departure from traditional distribution and transmission plans separately addressing their respective objectives and time horizons.

Distribution Planning 2.0

In 2018, EPRI launched a two-year initiative to modernize distribution planning and to develop new tools and procedures that can help utilities:

• Automate the design and evaluation of traditional and non-traditional planning alternatives
• Determine DER’s positive and negative effects on distribution systems
• Optimize investment across multiple planning timelines
• Evaluate how DER, increasing electrification, and changing customer demand may affect infrastructure investment
• Support integrated generation, transmission, and distribution planning

Researchers will develop tools (including software that vendors can build on and commercialize) to automate distribution planning, equipping planners to evaluate rapid DER deployment.

As a first step, EPRI is collaborating with utilities to identify gaps in planning tools and processes and to determine data collection necessary to guide future work. “Utilities will help us to define the capabilities the industry needs—both near-term and long-term,” said Smith.

The initiative expands on EPRI’s existing suite of planning tools, including:

• OpenDSS: Comprehensive distribution analysis tool that supports DER integration and grid modernization
• Distribution Resource Integration and Value Estimate (DRIVE): Evaluates feeder hosting capacity

“With input from our member utilities, we’re going to add new capabilities to the DRIVE and OpenDSS tools,” said Smith. “We will help vendors incorporate our tools’ features and our knowledge of distribution planning into the software they develop.”

“As solar, energy storage, and other DER technologies advance rapidly, distribution planning processes and tools need to keep pace,” said Smith. “This can enable planners to effectively evaluate all the options and design a system that provides customers with safe, reliable, cost-effective services.”

Reinventing Planning at Duke Energy

Duke Energy and EPRI are building a set of advanced planning tools to enable the utility to assess DER impacts and to automate functions that today are manual. For instance, the tools would automatically assess numerous factors relevant to a proposed battery installation, including its expected operating life, optimal location and size, and impacts on distribution, transmission, and generation.

The tools will factor data on future rooftop solar, predictions for future electric vehicle penetration, and changes in load and generation portfolios. “The more automation you need, the more precise your data has to be,” said Clif Cates, who oversees distribution planning at Duke Energy. “The data we used in the past is not real-time enough. We need precise data that can be shared among transmission, distribution, and generation.”

According to Cates, Duke Energy’s efforts to make its planning more holistic and dynamic required planners from different groups to meet regularly and to integrate distribution and transmission plans. “It’s challenging work, but it has helped the groups to understand one another better so that everyone could map out a shared direction,” he said.

Other power companies can benefit from this pioneering work. “We are building one of the first case studies on integrating transmission, distribution, and generation planning,” said Cates.

Artwork by James Provost

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